Heavy oil or bitumen can be produced from oil sands using a cyclic steam stimulation process. Steam generators are used to produce high-pressure steam, which is distributed and injected into the reservoir. Steam injection continues through a soak period until the oil viscosity is such that the oil can be pumped to the surface as a water/oil/gas mixture during the production part of the cycle and then returned to central plant facilities for separation and other downstream processing.
Steam generators may be fueled by a variety of different fuels to produce high-pressure steam for the extraction of bitumen from oil sands. Natural gas is the preferred fuel, but depending on its price, alternative fuels, such as whole bitumen or bitumen bottoms (resid, asphaltenes etc.) may be competitive. However, while alternative fuels may be price competitive, other problems may exist with their use including increased emissions due to the high sulfur content of such fuels. As a result, any use of bitumen as a fuel for bitumen recovery must include flue gas desulfurization (“FGD”) as an integral part of the process. More specifically, it is required that with the use of such fuels that sufficient scrubbing of the flue gas is conducted to adequately remove SO2 from the combustion emissions.
There are many commercial processes for FGD or scrubbing SO2 from flue gas. One technology for FGD utilizes limestone slurry or variations thereof. With this technology, the lime reacts with SO2 ultimately producing CaSO4, which precipitates out as fine solids in a slurry. The slurry itself must be adequately disposed of, usually by landfill or other means. In another technology, the use of a second alkali species (Double Alkali System) can increase SO2 removal and lower power consumption and scaling.
In a further technology, seawater can be used for scrubbing and is sometimes employed by power plants located in close proximity to the ocean. The inherent alkalinity of seawater (which may be supplemented with lime) reacts with and removes SO2 with efficiencies as high as 95%. However, seawater scrubbing results in an acidic seawater that must be neutralized (usually through dilution) to buffer the pH to that of fresh seawater prior to disposal.
Yet another technique for removing SO2 from flue gas involves scrubbing the gas with an aqueous solution of sodium hydroxide or ammonia. Conventional soluble alkali processes display efficient sulfur dioxide removal from flue gases. Ammonia-based sulfur scrubbing processes are described in the art and employ heat, acidification and crystallization techniques. However, ammonia-based techniques are disadvantaged having regard to the requirement of purchasing, storing and mixing the ammonia, as well as disposing of the resulting waste material. In some cases it is advantageous to employ forced oxidation of the reaction product and manufacture fertilizer from the resulting ammonium sulfate.
It is also known that alkaline materials including ammonia may be used to soften industrial process water by increasing the pH and precipitating CaCO3 and MgCO3. These processes are limited by the cost of the precipitating reagents compared to other options including the use of hydrated lime (Ca(OH)2). It is similarly known that basic materials such as aqueous sodium hydroxide or ammonium hydroxide (aqueous ammonia) may be used for scrubbing the acidic SO2 from flue gas. Again, these reagents typically have limited application due to the cost of the scrubbing reagents and the associated cost of waste disposal.
Thus, while individual processes for independently scrubbing SO2 and softening water are known, there continues to be a need for low cost processes. One way to achieve this cost reduction is to integrate water softening with flue gas desulfurization wherein only one chemical is required for both processes thereby resulting in a reduced cost and a significant reduction of waste material.
A review of the prior art reveals that such an integrated process has not been utilized. For example U.S. Pat. No. 5,683,587 discloses the use of reaction sludge produced from soda ash and lime treatment of seawater in FGD applications. More specifically, this patent teaches that ammonia (among other alkaline materials) may be added to the scrubber or ammonia may be added to the waste sludge to alkalinize it. U.S. Pat. No. 5,961,837 is a continuation of U.S. Pat. No. 5,683,587 and further discloses the use of biocides, corrosion inhibitors, polymers etc. in a variety of treatment applications. U.S. Pat. No. 4,321,241 teaches desulfurization of flue gas containing SO2, CO2 and other acidic components by washing in aqueous washing solution to which ammonia has been added in stoichiometrically necessary amounts for reaction with the sulfur oxides.
U.S. Pat. No. 4,853,193 teaches flue gas containing SOx and COx reacting with excess ammonia to reduce the NOx to N2. Unreacted ammonia and SOx are passed to a gas desulfurization zone to form an ammonium salt of an acid of sulfur which can be recovered and used as such or converted to elemental sulfur. U.S. Pat. No. 4,956,161 teaches a gas desulfurization process utilizing aqueous compositions of ammonium carbonate and ammonium bicarbonate and mixtures thereof.
U.S. Pat. No. 4,151,263 teaches a controlled process for the removal of sulfur oxides from gases by scrubbing with ammoniacal solutions in such a manner that the formation of sub-micron liquid particles is prevented at any point during the scrubbing operation, thereby preventing the formation of a plume emission in the vapour effluent from scrubbing.
U.S. Pat. No. 4,231,9956 teaches an ammonia double-alkali process for removing sulfur oxides from stack gases.
U.S. Pat. No. 6,289,988 teaches a process for the management of H2S containing gas streams and high alkalinity water streams where the H2S is selectively removed from the gas stream and combusted to form an SO2 rich waste gas stream. The SO2 gas stream is then scrubbed with the water stream to substantially remove the SO2 from the gas while subsequent treatment of the water such as softening or settling is improved. The capacity of this produced water to scrub SO2 is limited by its alkalinity content and the volume of water available for scrubbing. In other industrial application such as the combustion of high sulfur fuels such as coal or bitumen reside where the mass of SO2 requiring scrubbing exceeds the capacity of the produced water alkalinity, the scrubbing capacity of the water needs to be enhanced or supplemented.
Other examples of prior art process include those described in U.S. Pat. No. 6,383,261 which describes a process for management of industrial wastes including a water softening process, U.S. Pat. No. 6,149,344 which describes a process for acid gas disposal, U.S. Pat. No. 5,340,382 which describes an acid gas absorption process, U.S. Pat. No. 4,969,520 which describes a steam injection process for recovering heavy oil, U.S. Pat. No. 4,077,777 which describes a process for the neutralization of gases, U.S. Pat. No. 5,523,069 which describes a method for removing carbonyl sulfide from fluids, U.S. Pat. No. 4,774,066 which describes a process for purifying steam, and U.S. Pat. No. 4,968,488 which describes a process for removing hydrogen sulfide contaminants from steam.